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Taking its cues from a successful program in Connecticut, Rhode Island is poised to launch a new initiative to deploy solar and reduce electricity costs in homes owned by low- to moderate-income residents.
The Rhode Island Commerce Corporation recently issued a request for proposals from solar companies interested in partnering on the initiative, called Affordable Solar Access Pathways. The program will offer affordable leases for solar equipment on homes owned by residents with incomes less than or equal to 80% of the area median income. That’s a maximum of $65,460 annually for a family of four, or $44,512 for a two-person household.
“There will be no money down and net savings from day one,” said Vero Bourg-Meyer, project director at the Clean Energy States Alliance, or CESA, which collaborated with the Commerce Corporation to develop the program.
The homes must be located in environmental justice areas, as defined by the state Department of Environmental Management. Those areas are primarily in and around the cities of Providence, Pawtucket, Woonsocket and Newport.
That will enable the program to take advantage of the new environmental justice adders to the Investment Tax Credit passed as part of the Inflation Reduction Act. Those adders will allow solar system owners to qualify for a higher tax credit when homes are located in census tracts designated as environmental focus areas, Bourg-Meyer said.
CESA has been working to persuade states to develop more-inclusive solar programs by promoting Connecticut’s Solar for All program as a model. Under that program, the Connecticut Green Bank paid incentives to a solar company, Posigen, which was then able to offer a reduced price to customers for a 20-year rooftop solar lease.
The program helped drive a 185% increase in solar in low- to moderate-income communities in Connecticut between 2015 and 2018, according to a 2020 white paper.
Third-party ownership of the solar equipment was a critical aspect of that program’s success, Bourg-Meyer said, since lower-income customers are less likely to be able to obtain or afford financing.
Another key aspect was the program’s community-based marketing — “having neighbors speak to other neighbors about it,” she said.
Rhode Island’s program will be administered through the commerce agency’s Renewable Energy Fund, which will provide an initial $1 million in funding, in collaboration with the state Office of Energy Resources.
It’s not clear how many homes that $1 million will cover, as it will depend on how the program’s solar partner designs its program and incentives, said Shauna Beland, administrator of renewable energy programs at the energy office.
“The more creative they get the better,” she said.
There are no funds available to help out homeowners who need roof repairs in order to accommodate solar panels. But it’s possible that the solar installer will work with a roofing contractor and wrap those costs into the lease, something that is fairly common in Rhode Island, said Karen Stewart, manager of the Renewable Energy Fund.
The program should launch this spring.
Hawaii launched a solar program for low- to moderate-income homeowners last year, and Virginia is working on it, Bourg-Meyer said, adding, “it’s something that’s percolating across the country.”
Numerous studies have found widespread inequities in solar adoption across the country. However, a 2020 report from Lawrence Berkeley National Laboratory concluded that those disparities are gradually diminishing, with several states, including Connecticut, even demonstrating income parity between solar adopters and the broader population.
Massachusetts climate advocates say a clean heat standard proposed by state officials could fail to create meaningful progress toward decarbonization if it overvalues alternative fuels and doesn’t prioritize equity.
“The devil is in the details,” said Amy Boyd, vice president of climate and clean energy policy at the nonprofit Acadia Center, one of several environmental groups closely following the developing state policy.
In January 2022, then-Gov. Charlie Baker convened a Clean Heat Commission to develop strategies for decarbonizing the state’s building sector, which accounts for about 40% of its total emissions. Among its final recommendations released in November was the adoption of a clean heat performance standard.
The policy would create a system similar to a renewable portfolio standard but for heat instead of electricity. Heating fuel suppliers would be required to contribute to clean heat projects, likely by buying credits generated from activities such as heat pump installations and weatherization improvements. Over time, the amount of clean heat credits required would increase.
Other strategies recommended by the commission include reforms to state energy efficiency programs, establishing a climate bank to finance heat pump installations and weatherization projects, and scaling up workforce training to ensure there are enough contractors to perform the work.
As Massachusetts pursues its target of going carbon-neutral by 2050, buildings will be a major challenge. As of 2020, more than 80% of the state’s homes were heated primarily by fossil fuels. Switching to electric space and water heating would allow them to be warmed by electricity that includes an ever-increasing proportion of wind, solar, hydro and other renewable power.
While environmental advocates have praised most of the plans laid out in the Clean Heat Commission report, they are approaching the clean heat standard with more of a cautious optimism. Most believe the standard is inevitable, but are paying close attention to the details.
“The Clean Heat Standard is unavoidable in some form,” said Larry Chretien, executive director of the Green Energy Consumers Alliance. “We want to make sure that we put disadvantaged folks at the front of the line, and we want to make sure it is legit clean heat.”
In December, the state released its Clean Energy and Climate Plan for 2050, which confirms the current administration’s vision for developing a clean heat standard, setting a target date of implementation by early 2024. Governor-elect Maura Healey is widely viewed as a clean energy champion, but it still remains to be seen how she will develop and build on her predecessor’s work.
Advocates agree that, as the program develops, it will be essential to pay attention to what, precisely, counts as clean heat. Electric heat pumps will be central to any strategy, but it is almost certain that alternative fuels will also be proposed as qualifying for clean heat credits.
Major gas utility National Grid, for example, has declared its intention to replace the fossil natural gas it currently delivers with renewable natural gas and green hydrogen by 2050. Renewable natural gas is derived from natural sources, such as composted animal manure or food waste, and the production process may recapture some greenhouse gases before they are released into the atmosphere.
However, its full lifecycle carbon emissions are highly variable and may or may not be lower than those of conventional natural gas. Further, renewable natural gas is chemically identical to fossil natural gas, so it still releases carbon dioxide when burned, leaks from pipes into the atmosphere, and carries health risks when used indoors.
Also, a recent study commissioned by California regulators found that hydrogen concentrations above 5% in the natural gas system can damage pipes and require appliances to be modified.
National Grid has confirmed its view that renewable natural gas and green hydrogen should be part of a clean heat standard, arguing that electricity alone will not be enough to decarbonize heating systems in a region that experiences as much cold weather as New England.
“As suggested in the recent Clean Heat Commission report, low-carbon fuels provide an opportunity to reduce emissions, which supports our shared decarbonization, climate action and environmental justice goals,” the utility said in a statement.
However, any clean heat credit that is given to these fuels should depend on a rigorous analysis of lifecycle emissions, said Caitlin Peale Sloan, vice president for Massachusetts at the Conservation Law Foundation. Giving too much weight to alternative fuels could slow down the needed transition to electrification, she said.
“The way they count emissions from alternative fuels — that’s going to be the ballgame in many respects,” she said. “The longer you push off the switch to electrification, the more expensive it’s going to be and the harder it’s going to be.”
Advocates also argue that running new fuels through old pipes is mostly a way for utilities to keep their distribution business afloat as the region transitions away from fossil fuels and will only slow the pace of needed carbon reductions.
“That’s going to continue to be a difficult dialogue, because of the gas companies facing the threat of stranded assets,” said Matt Rusteika, director of market transformation at the Building Decarbonization Coalition.
Another major concern is equity. Lower-income residents are more likely to live in some of the state’s oldest and draftiest buildings, while, at the same time, having less money and power to weatherize their homes and upgrade their heating systems.
“Centering equity and engagement — it doesn’t get into a whole lot of detail as to how to do that, but keeping that as a tentpole of all of our decisions going forward is crucial,” said Boyd, of the Acadia Center.
A clean heat standard can generate more revenue to tackle this problem, advocates said, but the state will need to shift some policies and priorities to use the money to the best advantage. Boyd pointed to existing rules in state efficiency programs that won’t provide services to homes that have mold or outdated knob-and-tube wiring systems. The system offers some money to help with these fixes, but the reality is that few property owners go through the full process of making the repairs and pursuing weatherization and electrification.
“So now not only is the tenant stuck with mold that the landlord won’t fix, they don’t get weatherization and still have to breathe in gas fumes,” Boyd said.
To create an equitable system, it would be important to channel money from a clean heat standard into programs to upgrade and repair these homes, she said.
A study by the Regulatory Assistance Project, prepared as part of the development of the 2022 Massachusetts Clean Energy and Climate Plan, suggests other ways a clean heat standard could promote environmental justice. The standard could include a carve-out requiring that an increasing percentage of clean heat credits come from projects serving low- and moderate-income homes, for example. Or the parties required to meet the clean heat standard could receive bonus credits for reaching a certain threshold of credits from projects supporting disadvantaged residents.
Though the proposed details are yet to be rolled out, it will be vital for any clean heat standard to be coupled with complementary programs and incentives to make a decisive move away from fossil fuels, advocates agreed.
“The clean heat standard alone is not a silver bullet,” Boyd said. “It still needs to be combined with a clear plan for pruning the gas system.”
When the Crawford coal plant in Chicago’s Little Village neighborhood closed in 2012, residents hailed it as a victory for public health and environmental justice. But now a Target warehouse sits in place of the coal plant, with a constant stream of diesel trucks posing a new health threat and source of greenhouse gas emissions.
The neighborhood is just one example, local leaders and statewide advocates say, of why Illinois should adopt rules and programs moving toward electrification of medium- and heavy-duty trucks — starting with the Advanced Clean Trucks rule pioneered by California and now on the books in seven coastal states.
“Because of past decisions going back 170 years, we are without a doubt the freight and rail hub of North America — these freight facilities aren’t going anywhere,” said José Acosta, senior transportation policy analyst for the Little Village Environmental Justice Organization. LVEJO led the fight to close the city’s two coal plants and fought against the construction of the warehouse on the coal plant site.
“If that’s the case, how do we mitigate all the impacts of it?” Acosta added. “The most pressing impact is the air pollution impact, the threat of PM2.5” — fine particulate matter — “nitrogen oxide and other things that have an impact on community health. That’s why it’s so important to electrify fleets.”
LVEJO is among the coalition of environmental, community and labor groups called NET-Z demanding the state adopt the Advanced Clean Trucks rule, or ACT. The rule would mandate that electric or hydrogen fuel cell vehicles make up an increasing percentage of heavy- and medium-duty trucks sold in the state. With different benchmarks for different types of vehicles, the rule would mean almost all new trucks and delivery vans would be zero-emissions by 2040. Given fleet turnover, experts estimate this means almost all trucks on the roads would be zero-emissions by 2050.
The coalition is also calling for the adoption of the Heavy-Duty Omnibus Rule, which would mandate stricter nitrogen oxide emissions controls on new fossil fuel trucks. Meanwhile, a bill introduced in the state legislature would ask the Illinois Environmental Protection Agency to offer $200,000 vouchers for the purchase of class 7 or 8 large trucks, provided a diesel truck is scrapped in return.
“It is not like all the trucks sold have to be electric” immediately under the Advanced Clean Trucks rule, noted Illinois clean energy advocate J.C. Kibbey of the Natural Resources Defense Council. “It’s a very gradual ramp,” and the omnibus emissions reduction rule could be “the peanut butter to the ACT’s jelly,” reducing emissions from fossil fuel trucks as the transition to zero emissions plays out.
In May, the Respiratory Health Association published a study showing that Illinois ranks fifth of all states in the number of deaths per capita attributed to diesel pollution. And 12 Illinois counties, most of them in the Chicago area, are among the top 9% of counties nationwide for exposure to fine particulate matter from diesel.
“People are getting sick and dying from what they’re breathing from the tailpipes,” said Brian Urbaszewski, environmental health programs director for the Respiratory Health Association. “And global warming is happening — when you look at who gets hurt most or first by those increasing extreme weather events, it’s going to disproportionately hit those lower-income vulnerable communities.”
Cleaning up trucks is also an environmental justice issue for workers in warehouses and other sites with heavy truck traffic. Warehouse Workers for Justice, an organization that has long fought for better conditions for workers in Chicago-area warehouses, is a leader of the NET-Z coalition.
So far coastal states — California, Washington, Oregon, New York, New Jersey, Massachusetts and North Carolina — have adopted the Advanced Clean Trucks rule, and 10 other states have signed memoranda of understanding agreeing to similar provisions. Illinois could be the first Midwest state to adopt the measure.
A study commissioned by the Natural Resources Defense Council and Union of Concerned Scientists found that medium- and heavy-duty vehicles make up only 7% of the vehicles on the road in Illinois, but account for more than a third of their greenhouse gas emissions and about two-thirds of nitrogen oxide and fine particulate matter (PM2.5) emissions.
The NRDC-UCS study used modeling to estimate that the least aggressive of three possible scenarios — the adoption of California’s Advanced Clean Trucks rule — would result in “up to 310 fewer premature deaths and 347 fewer hospital visits from breathing polluted air.” The study also found massive fuel savings to vehicle fleets and savings to electric customers, since the increased electricity sales for vehicle charging could help utilities lower residential rates. “Under the ACT scenario, by 2050 annual cost savings for Illinois fleets are estimated to be $1.2 billion, and annual bill savings for electric utility customers in the state could reach an estimated $62 million,” the study found.
Modeling also looked at the adoption of the emissions-reducing omnibus rule along with the ACT rule, and at a most-aggressive scenario that would see almost all new trucks being zero-emissions by 2040. Those scenarios yielded greater health and economic benefits than the ACT rule alone.
The study noted that there are currently more than 615,000 medium- and heavy-duty vehicles on the road in Illinois, ranging from heavy-duty pickups and vans to semi-trailers. The rules would cover only new vehicles, and only vehicles sold by manufacturers in Illinois, not those purchased out of state.
Kibbey explained that the ACT rule would be enforced through a system of credits: “The standard is implemented as a percentage of total truck sales per manufacturer in the state. They can buy, trade, and store credits. In addition to the manufacturers’ ability to price and market trucks in ways that increase sales, the crediting system allows for a lot of compliance flexibility. If a manufacturer doesn’t fulfill its credit deficit in a given year, they incur a financial penalty based on the class of vehicle, and the deficit rolls over to the next year. If they don’t address the deficit, they will continue to incur penalties.”
The NRDC-UCS study notes that a higher proportion of components for zero-emissions vehicles are manufactured out of the country and must be imported. The net macroeconomic benefits of a national transition to zero-emissions vehicles, therefore, depend on the extent to which the U.S. ramps up manufacturing of such components. This sector holds potential especially for states with a rich industrial history and infrastructure like Illinois, advocates say.
“This is such an opportunity for us, this is not a hair shirt,” Kibbey said. “This is an opportunity not only to add jobs in the clean transportation sector … but to be the best state in the country to drive and manufacture an electric vehicle. If we want to build them here, let’s create a market for them here.”
Last year the electric truck manufacturer Rivian opened a factory in Normal, Illinois, in a shuttered Mitsubishi factory. Rivian’s R1T electric truck produced in Normal was voted the state’s “coolest” product made in Illinois in a contest hosted by the governor’s office this year. As Capitol News Illinois wrote, the R1T is the “first electric truck in production that features four motors, eight driving modes and up to 400 miles of range on a single charge, combining off-road capabilities with the driving style of a sports car.”
The Canadian electric bus and truck manufacturer Lion Electric also has a factory in Joliet, the Chicago-area city that is also home to one of the nation’s largest warehousing hubs. This fall, the company produced its first electric school bus in the Joliet factory.
Buses would be covered by mandates in the Advanced Clean Truck rule. Meanwhile, funding from the Inflation Reduction Act and various other incentives exist for electric buses, including funds from the Volkswagen lawsuit settlement that Illinois has earmarked for electric school buses.
“We’re making [electric trucks] in Illinois,” Urbaszewski said. “The problem is we’re not providing the environment to make sure they stay here and drive on Illinois roads, providing the pollution reduction and health benefits.”
The electrification of transportation in Illinois is especially appropriate given that the state’s energy law passed last year mandates the electricity generation sector phase out fossil fuels by 2045, meaning electric vehicles would be charged with clean power.
“We’re not just going to be moving emissions around to a natural gas or coal plant that will make electricity to run an electric truck — we’re reducing in a real sense,” Urbaszewski said. “Pushing electric vehicles makes sense because it gives you added benefits to what we’re doing in the power sector.”
Illinois’ investor-owned utilities ComEd and Ameren are launching beneficial electrification plans mandated by the state’s 2021 Climate and Equitable Jobs Act, investing hundreds of millions in electric vehicle incentives and charging infrastructure. And the Inflation Reduction Act provides tax credits of up to $40,000 for commercial electric vehicle purchases and up to $100,000 for electric vehicle charging infrastructure.
The NRDC-UCS report noted that the Advanced Clean Trucks rule could mean that total electricity demand in the state increases by 1.3 million megawatt-hours in 2030 and 12.7 million MWh by 2050, an estimated total of 1.3% and 12.9% of Illinois’ electric load in those years. (The study notes that “current annual electricity sales to residential and commercial customers in Illinois total 74.2 million MWh and are projected to grow to 83.8 million MWh in 2050.”)
But that new demand would be met with clean energy and by charging vehicles at night when demand is otherwise low, advocates say.
“As long as you have the rate structures in place, the infrastructure in place, it shouldn’t put much strain on the grid,” Kibbey said. “Since the grid isn’t used that efficiently, we build it bigger than we need for most of the time. In Illinois at night, we have a bunch of nuclear energy, a bunch of wind energy” that’s not needed. “If you are charging [electric vehicles] off-peak, it not only avoids creating problems with the grid, but we end up using the grid more efficiently.”
Despite continuing a lawsuit over the state’s clean car standards, the Minnesota Automobile Dealers Association recently hired an electric vehicle program director.
The organization believes it is the first dealer association in the country to add a staff member assigned explicitly to electric vehicle issues. Its vice president of public affairs, Amber Backhaus, said the position developed over the past two years as demands by dealers for expertise and information on electric vehicles grew.
Backhaus said the dealer association does not agree with “supply side mandates,” but does not see that as contradictory to preparing for the market shift that is already well underway.
“Electric vehicles are the wave of the future and our dealers are excited to sell them, but there are a lot of things they need to do to prepare to be able to sell them,” she said. “We get a lot of questions from dealers and we thought it would make sense to bring somebody in-house who could put together those resources and answer their frequently asked questions.”
The association selected Steve Nesbit, a former executive who oversaw electric vehicles and renewable energy programs at an electric cooperative and worked at an auto dealership. Nesbit said he sees his role as helping dealers “support the sale of electric vehicles and keep their business model operating.”
Nesbit worked for Wright-Hennepin Cooperative Electric Association for 12 years, focusing on renewable energy and community solar for part of his time there. Before taking the association job, he worked for an energy technology company and an auto dealer.
The association has been a long-term member of Drive Electric Minnesota, an initiative of the Great Plains Institute. M. Moaz Uddin, a policy specialist at the institute, said the addition of Nesbit will help “bridge the gaps between dealerships and utilities” and make for a smoother transition to vehicle electrification.
While electric vehicles will play a crucial role in decarbonizing transportation, they will not be the only solution. Minnesota needs to continue efforts to create low-carbon fuels and communities where residents can walk or use transit, bicycles and other transportation modes instead of cars, Uddin said.
Nesbit starts his role as the association continues fighting the state’s clean cars standards in a case heard in November at the Minnesota Court of Appeals. Last year, Minnesota adopted the clean cars standards developed by the California Air Resources Board, a move requiring dealers to make more electric vehicles available starting in 2024. The Minnesota Pollution Control Agency oversees the new rule.
Auto dealers and Republicans have criticized the Walz administration’s embrace of the California model. The federal government only permits California to have its own auto emission regulations. However, it allows other states to follow the Golden State’s rules or those of the U.S. Environmental Protection Agency.
More than a dozen states have embraced the tougher rules, but California’s decision to ban the sale of internal combustion engine vehicles in 2035 has left several states, including Minnesota, debating whether to return to the federal standard. Backhaus expects the appeals court to release a decision early next year, which comes after the association lost an earlier challenge in federal court last year.
Fresh Energy, which publishes the Energy News Network, is one of six organizations that have signed on to a brief of amici curiae in support of the tougher standards. Fresh Energy policy staff do not have access to the Energy News Network’s editorial process.
Both Backhaus and Nesbit say the lawsuit does not diminish the association’s embrace of electric vehicles nor its desire to help members overcome challenges. Dealers may not like the speed of the transition, Nesbit said, but they understand the need to educate sales and service staff on the new technology.
They must learn how to speak to consumers about the strengths and weaknesses of electric vehicles in weather conditions in Minnesota, such as brutally cold winters that can diminish battery charges quickly, he said.
Backhaus said automobile manufacturers have begun requiring dealers to have chargers onsite and new equipment in repair shops. Dealers will need new lifts — because electric vehicles weigh more than internal combustion vehicles — and a retraining program for their mechanics. Ford recently announced new requirements could cost individual dealerships $1.2 million in upgrades, she said.
Minnesota dealers work with 65 different investor-owned, cooperative and municipal-owned utilities, Backhaus said. Some utilities, especially those owned by municipalities, have little experience with electric vehicles or chargers. Auto sellers will need onsite chargers, as will their clients.
“Hopefully, we can also educate utilities serving our dealers, so this is a smooth transition,” Backhaus said.
Tom Leonard, incoming chair of the association and president of Fury Motors in the Twin Cities, has become a big fan of electric vehicles and of the association adding a staff expert devoted to training, education and advocacy. The lawsuit, he conceded, may have led Minnesotans to believe dealers don’t want to sell electric vehicles.
“That’s a massive misperception that has been maybe played more in the media than in the car dealership world,” he said. “Car dealers are very pro-electric vehicles, zero-emission vehicles. We don’t want to be behind what’s coming at us.”
Leonard said he will have to upgrade his dealership, which sells Chrysler, Jeep and Dodge vehicles. The association has been working with manufacturers about how infrastructure charging investments work in Minnesota, for example by pointing out that state funding requires the public to have access to the equipment. Many dealerships must start installing chargers and new equipment early next year to meet 2023 car company deadlines, he said.
Backhaus said auto manufacturers have not yet created programs to help dealers pay for upgrades. The association plans to look for funding for members through federal and state sources. The Inflation Reduction Act offers a 30% tax credit from charger installations, but some of the other initiatives come with “a lot of red tape,” she said.
The association plans to continue advocating for legislation in Minnesota to offer incentives for electric vehicle purchases and develop a program to help dealers pay for upgrades. Rep. Zack Stephenson, a Minneapolis Democrat, has sponsored legislation that offers rebates for buyers and assists in helping dealers pay for programs certifying employees to sell electric vehicles.
In the next few years, Backhaus would like to see dealers have the educational background, infrastructure and services in place to sell EVs.
“We want them to be able to talk to their consumers about how [electric vehicles] work and that they’re not a scary, unknown thing,” she said.
By now, solar trailblazer Tony Smith figured he would be on the verge of linking at least 100 low-income households in Virginia’s Shenandoah Valley with affordable power from the sun.
Secure Solar Futures, the Staunton-based company he leads, had selected an ideal 10-acre, south-facing site in Augusta County for the 1.2-megawatt project. It carried a $2 million price tag and was set to go online after July 2023, per Virginia’s recent community solar law.
County officials heartily embraced Smith’s plan and praised his vision to preserve the region’s agricultural traditions by grazing sheep among the arrays.
And, in the spirit of a true community solar venture, the developer had partnered with an energy-centric nonprofit in nearby Charlottesville to identify potential customers.
“People want to feel a connection to where their energy is produced,” Smith said about seeking local customers. “That’s part of our game plan.”
What could possibly derail such a well-intentioned plan?
As it turns out, plenty.
But the major obstacle emerged when Smith broached Dominion Energy in August 2021 about interconnecting the project to the distribution grid.
Dominion rejected the proposal. In the ensuing back-and-forth, Secure Futures discovered that Plan B would mean footing an extra $1 million bill to install a type of fiber optic wire known as dark fiber between the array and the substation to meet Dominion’s standards.
“Suddenly, the project would cost $3 million,” Smith said. “That made it too expensive. To make it appealing to low-income customers, the price has to be less expensive than the rate they’re already paying to Dominion.”
For distributed energy, Dominion frames dark fiber as a reliability and safety necessity. In tandem, the utility insisted that Smith’s proposed array be able to go offline within one-sixth of a second of a power outage being detected.
That surprise blink-of-an-eye demand has stalled Smith’s array — but not his resolve.
“We were shocked to get this news from Dominion, because no other utility has these requirements,” he said, noting a two-second shutoff is the industry standard. “But we’re still trying to make this project happen.”
Dominion spokesperson Jeremy Slayton didn’t comment on this specific case.
Generally, he said, the utility administers regulations laid out in Chapter 314 of the Virginia code that governs the interconnection of small electric generators in a “consistent and equitable manner” for all customers that “desire to operate generation in parallel with the Company’s distribution grid.”
He added that Dominion performs site-specific, customized interconnection studies to identify modifications needed to ensure the safety, reliability, and operability of the grid.
In May, the State Corporation Commission opened a docket to comprehensively explore interconnection issues related to distributed energy resources.
“Dominion … looks forward to continuing to participate in this docket as it evolves,” Slayton said.
For Smith’s project to come to fruition, Virginia’s solar industry will likely have to convince utility regulators that developers in Dominion territory, especially small ones, not be saddled with installing expensive dark fiber when other — and cheaper — existing technology can meet the same safety and reliability standards.
Dominion evidently insists that dark fiber should be the heart and lungs of grid equipment known as Direct Transfer Trip, or DTT.
The Chesapeake Solar & Storage Association, or CHESSA, challenged Dominion’s dark fiber assertion in testimony submitted to Virginia utility regulators this summer.
“This [DTT] requirement is an unnecessary and arcane approach to addressing anti-islanding, given the fact that certified inverters already perform this function,” said GreeneHurlocker attorneys representing CHESSA.
With DTT costs averaging $2 million to $3 million — and reaching as high as $7 million, CHESSA and Coalition for Community Solar Access have withdrawn multiple projects in Virginia.
CHESSA noted that states with high levels of distributed energy penetration have “long moved away from requiring DTT and instead use inverter-based solutions.”
Virginia solar developers agree that it’s unfair for the first project in the queue at a substation to bear the financial brunt of an entire substation upgrade that essentially becomes a grid modernization project. CHESSA also noted that some states are exploring the idea of cost-sharing among distributed energy projects.
Cliona Robb, an energy attorney for 22 years, is frustrated that Smith’s project is being stymied by Dominion’s dark fiber rationale when she says the utility is clearly an outlier on that front. In August, she filed comments with the commission on behalf of Secure Futures.
“The message is that you can get solar, as long as it’s utility solar. Otherwise, you’re out of luck,” said Robb, of Richmond-based Thompson McMullan. “It’s outrageous to me that a utility can unilaterally adopt a practice that’s not consistent with industry standards.”
In her comments to regulators, she outlined several changes that would help smaller solar developers complete projects without bankrupting themselves.
For instance, Robb urged commissioners to adopt a rule eliminating the need for dark fiber for interconnections under 5 MW. In Virginia, Level 2 interconnections generally apply to projects between 500 kW and 2 MW, while Level 3 projects can be up to 20 MW.
As well, she advised that expenses for those smaller projects be limited to the cost of inverters and reclosers and not costs related to upgrades to a utility’s substations or other pieces of its distribution system. As well, she said, inverters or cellular communications should be the standard in lieu of dark fiber.
Robb pointed to a case study published by the Institute of Electrical and Electronics Engineers (IEEE) concluding that DTT cellular communications provided an efficient and cost-effective approach for utility communications with distributed generation systems.
The study looked at three installed DTT systems — one in Central Virginia Electric Cooperative territory and two in Dominion’s service area. It compared copper telephone lines to cellular communications. The latter was considered because the authors noted that fiber installation is not always feasible because it can be cost-prohibitive.
The Institute of Electrical and Electronics Engineers is the professional body that sets scores of standards, including one that covers inverters and minimum distributed energy performance requirements. Secure Futures and other developers maintain that Dominion’s strict interpretation of that standard is squeezing their projects.
Even if Secure Futures did splurge on fiber optic cable for its Augusta County project, Smith noted that it would be using only two of the 24 total “strands.”
“So, the other 22 fibers would be dedicated to some other purpose not involving our project,” Smith said. “With that, Dominion is putting the cost of infrastructure development on the backs of solar developers.”
Slayton, the Dominion spokesperson, said the inverter performance criteria is not related to the dark fiber requirement. He noted that the inverter specifics had been among the utility’s protection requirements since September 2016.
Utilities, installers, environmental advocates and others in the solar community flooded regulators’ inboxes after the May request for comments.
Two of the eight questions commissioners asked participants to address small solar generators. In addition to dark fiber, solar advocates weighed in on a number of interconnection concerns, including lengthy timeliness, excessive studies, lack of transparency and dispute resolution.
The state General Assembly recognized the benefits of distributed energy by passing both the Virginia Clean Economy Act and a shared solar statute in 2020.
Those and other clean energy laws prompted regulators to update interconnection rules from more than a decade ago. However, advocates had complained that those tweaks weren’t adequate enough to match the rising volume of interconnection applications.
“While the changes made to the rules provided modest improvements to the process, the distribution interconnection process continues to be antiquated and ill-prepared for the 21st century grid,” CHESSA wrote. “The existing procedures [are] not sufficient to enable the amount of renewable energy additions required by the Commonwealth’s transformational energy goals.”
Dominion submitted 15 pages of comments. Two of those pages addressed regulators’ query about how commissioners could facilitate its approach to the Institute of Electrical and Electronics Engineers standard on inverters and distributed energy.
Dominion stated that it believes any use of distributed energy “ride-through or voltage regulation functionalities should be at the Company’s discretion and evaluated based on system needs on a case-by-case basis.”
The utility told commissioners that the regulations centering on the standard don’t need to be revised.
“Specifically,” commission staffers summarized, “Dominion commented that anti-islanding functions of [distributed energy resources] inverter-based resources alone do not replace the multiple functions and layered protection that DTT provides to the electric power system.”
On Sept. 19, commission staff released a 57-page action plan, of sorts, after reviewing input. They concluded that some concerns could be addressed immediately, others would be more time-consuming and still others would likely require a separate docket.
“The requirement for usage of dark fiber-optic cable for DTT implementation was one of the most pressing issues commented on by the parties,” commission staffers said.
Solar developers echoed Secure Futures’ concerns about dark fiber. However, they also pointed out that the fiber can cost more than $250,000 per mile to install. The total price tag is a blow to project planners because utilities don’t deliver those cost estimates until the “facilities study phase,” the final study phase of a long and involved process.
Smith said he is disappointed that working groups will likely be handling the issues delaying his Augusta County project — dark fiber and the excessive cost of interconnection — in a far-off timeline.
“We have a need for speed,” he said. “But we’re looking at four to six years until anything is settled.
“In the meantime, while Rome burns, solar investment will bypass Virginia. Social policy and interconnection barriers are hindering the promise of solar.”
Robb, his attorney in this case, said commissioners need to be aware of the damage they are inflicting by pushing immediate concerns off to slow-moving work groups instead of acting themselves.
“Not advancing community solar is harming the public interest,” she said.
Smith, who founded Secure Futures in 2004, is no clean energy rookie. The entrepreneur has been immersed in solar since 1978 when he created his first job in the industry with the Philadelphia Solar Energy Association.
Thus far, his Staunton company has developed more than 11 MW of arrays in Virginia, West Virginia and the Carolinas.
Five years ago, the business became a certified B Corporation to reflect its commitment to solving social and environmental problems. It prides itself on innovations in financing, public policy and energy education that extend the reach and affordability of solar power.
For instance, that spirit is reflected in an endeavor Smith’s company is undertaking in the state’s seven historic coalfield counties, at the behest of the Solar Workgroup of Southwest Virginia.
A public-private partnership launched in September 2020, appropriately named Securing Solar for Southwest Virginia, is in the midst of installing 12 MW of solar arrays at five commercial buildings, five multifamily housing units and 10 schools. The optimistic completion date is next year.
Relatedly, Smith viewed the Augusta County project as an innovation to connect underserved Virginians with community solar, a new concept in Dominion territory.
He praised the utility for setting up a program but lamented how interconnection challenges are “killing it on the implementation side.”
Dominion’s program, set to debut next year, sprang from state legislation passed in 2020. Initially, total capacity will be capped at 150 MW. Both solar and environmental justice advocates had lauded the law for requiring that at least 30% of the enrolled customers qualify as low-income. If that bar was met, the program could grow by another 50 MW.
In addition, no single community solar project could be larger than 5 MW. The idea was to incrementally stimulate a series of small-scale distributed generation projects, roughly 1 MW apiece.
This summer, regulators set off an uproar among solar advocates by allowing Dominion to charge a $55 monthly minimum fee to enrollees. The legislation had included a measure allowing commissioners to set a monthly fee that let Dominion account for costs of implementing shared solar and for use of the grid infrastructure.
Low-income subscribers, however, are exempt from that minimum fee. Aiding that poorer audience is why Secure Futures sought out a local collaborator in Augusta County.
Now, that affiliation also might be unraveling.
Due to delays, it’s not clear where the partnership with the Charlottesville-based Local Energy Alliance Program now stands. Leaders of the nonprofit didn’t return requests for comment. Since 2010, LEAP has offered home and commercial energy upgrades, as well as solar services.
Even though Smith has “come to the sad conclusion that we’re not going to get any help on the regulatory level,” he is forging ahead.
After withdrawing the project in April, Secure Futures is now in the midst of resizing it and preparing a new interconnection application.
“We’ll see what happens,” Smith said. “We’re not holding our breath.”
Wisconsin solar advocates want regulators to look to Iowa’s example as they consider the latest skirmish over how solar projects are financed in the state.
The Wisconsin Public Service Commission is considering two petitions seeking authorization for third-party-owned solar projects, in which the entity that owns the array is different from the property owner that will use the electricity.
The financing mechanism makes solar viable for many cities, schools, and nonprofits, as well as residential customers who can’t afford the upfront cost of a solar array. It’s also been the subject of a long legal and regulatory battle between solar advocates and Wisconsin utilities that see it as a threat.
That was once true in Iowa, too, until 2014 when the Iowa Supreme Court affirmed that a third party can own a solar array and sell the power, or make lease payments, to the owner of the property without becoming a public utility. In the eight years since then, experts and advocates say utilities’ fears over such ownership opening the door for “deregulation” or other negative impacts have not materialized.
“Iowa is still very much a utility-dominated state with a vertically integrated utility structure, and with less than 2% of generation from distributed resources,” said Karl Rábago, an energy consultant based at Pace University School of Law, testifying on behalf of the advocacy group Vote Solar in one of the pending cases. “Moreover, since the 2014 court decision, I am not aware of movement in the state toward deregulation or retail choice.”
(Rábago also provides occasional editorial feedback to the Energy News Network as a member of a reader advisory committee. See our code of ethics for more information.)
Iowa’s court decision resulted from Dubuque-based developer Eagle Point’s lawsuit challenging Alliant Energy’s refusal to interconnect a third-party-owned array to the grid. Eagle Point has also been central to the standoff in Wisconsin, after utility We Energies refused to interconnect solar co-owned by Eagle Point and the city of Milwaukee.
The latest petitions related to third-party solar in Wisconsin were filed in May. Vote Solar asks that the Wisconsin Public Service Commission allow a Stevens Point family to enter a third-party ownership arrangement for an 8.6-kilowatt system. The petition notes the energy savings would help them pay for college for their two teenage children, and a third-party structure is necessary to avoid upfront costs. That family lives in territory served by Wisconsin Public Service Corporation, which like We Energies is a subsidiary of utility company WEPCO.
The Midwest Renewable Energy Association petition asks the commission for a declaratory ruling clarifying that third-party solar is legal, and notes that it would be too expensive and difficult for every customer who wants the arrangement to file their own petitions.
Public hearings for both proceedings will be held on Nov. 2, and public comments are being accepted through Nov. 9.
“There is simply no reason to believe that Wisconsin’s experience with third-party-financed distributed energy systems would track any differently than what we’ve seen in Iowa,” said Michael Vickerman, program and policy director for Renew Wisconsin. “Third-party financing will not usher in mass defections from the grid, nor will it, by itself, push energy rates higher. But it would certainly broaden the customer base that Wisconsin solar contractors would serve, including low- to moderate-income households who will have less success accessing federal tax credits than their more affluent counterparts.”
A 2021 report by Iowa’s state auditor showed that a total of 80 public entities had installed solar, mostly since the 2014 court decision, saving an average of over $26,000 a year on energy as a result. The report noted that schools have hired an extra teacher, avoided closing and otherwise benefited from the savings.
Since the Iowa ruling, Eagle Point has developed dozens of third-party-owned installations for Iowa schools and municipalities, including recent arrays installed on the fire station and water treatment plant in the city of Hills, Iowa, and a 300-kilowatt array for Upper Iowa University. Eagle Point CEO Jim Pullen said the company has signed about 20 contracts with municipalities just this fall.
“It’s not that complicated,” Pullen said. “By and large I don’t believe the utilities have made any statements about [third-party ownership having] deregulated the market or destabilized the market. They treat a third-party project exactly the same as a customer-owned project. There’s no difference from our perspective when we’re interconnecting, and they don’t seem to care anymore.”
The utilities that had opposed third-party ownership in Iowa — Alliant Energy and MidAmerican Energy — did not respond to questions about their past opposition to third-party financing or its current impact. Spokespeople for both utilities said the companies support renewable energy and offer options for customers to access renewables, including an Alliant program wherein the utility pays customers to place utility-owned solar on their rooftops.
“Alliant Energy focuses on making renewable energy accessible for everyone — in order to keep it affordable for everyone,” says a statement provided by Alliant. “We support energy policies that ensure a fair, affordable and reliable energy network for all customers and communities. … We support our customers’ interests in solar through a variety of mechanisms, including utility-scale solar, community-based solar and interconnection of customer-owned systems.”
The Iowa state auditor’s report notes that Iowa has 99 counties and 330 school districts. “If each county, each county seat, and each school district created a solar installation of the average size of these installations [already developed with third-party ownership], over the installations’ lifetimes Iowa taxpayers could expect to net over $375 million in savings,” the report says.
The Iowa state auditor also surveyed schools and cities about public reaction, and found significant public support. The Bennett Community School District, for example, credited its $53,000 energy savings for helping to keep the school open to its 88 enrolled students. The city of Cedar Rapids received feedback that its panels — developed with Eagle Point — were unattractive, and planted trees to improve the view.
“At a high level, third-party ownership is doing exactly what we thought it would do” in Iowa, said Josh Mandelbaum, a senior attorney with the Environmental Law & Policy Center: “Providing greater choice and flexibility for individuals and organizations that want to pursue solar.”
We Energies and other utilities have argued that third-party ownership undermines the utility’s ability to keep up the grid and serve its customers, since the third-party owner is essentially competing with the utility and the customer is paying less to the utility. The Wisconsin Utilities Association offered expert testimony during the petition proceedings — including from a former California utility commissioner — regarding the negative impacts of net metering and solar proliferation.
But Environmental Law & Policy Center senior attorney Brad Klein argued that this “cost-shifting” argument, often made by utilities nationwide, is separate from the legal question of whether a third-party owner is functioning as a utility.
“Some of the arguments you see are not specific to the legal question regarding whether providing financing options creates a public utility; they are more broadside attacks on distributed energy resources generally,” Klein said. “We saw that in Iowa — a mischaracterization of the impact of third-party financing.”
Meanwhile, the idea that distributed solar unfairly shifts costs to customers without solar and jeopardizes grid reliability has been widely challenged with evidence showing more distributed solar generally makes the grid more efficient and resilient, benefiting all customers.
“The impact of third-party financed solar on Iowa’s electric rates? Negligible,” said Renew Wisconsin’s Vickerman. “If anything, the gap between Iowa’s and Wisconsin’s electric rates has widened since 2014.”
The Environmental Law & Policy Center cites a 1911 Wisconsin Supreme Court case, Cawker v. Meyer, wherein the court ruled that a company selling heat and power to several neighbors did not constitute a public utility because of its limited scope. Case law says utilities’ rights to operate as regulated monopolies must be protected for the interest of customers, not the utilities’ competitive interests, furthering the argument for third-party solar as advocates see it.
Once third-party financing becomes commonplace, the success and popularity of such arrays depend in part on net metering policies that typically apply equally to directly owned and third-party-owned projects.
In Iowa, advocates say utilities have done nothing since the Supreme Court decision to impede third-party-owned arrays specifically, but struggles over distributed solar continued. The Environmental Law & Policy Center and other advocates were upset with a 2019 utility-backed bill that would have gutted net metering for all distributed solar, including third-party-owned arrays. Ultimately 2020 state legislation established inflow-outflow billing that will transition to a value-of-solar tariff. That compromise was supported by clean energy groups, though they have clashed with utilities over its implementation.
Third-party ownership allows nonprofits like schools, government agencies, churches, hospitals and social service agencies to collect tax benefits even though they do not pay taxes, since a private developer owns and operates the solar installation, passing their tax savings on to the customer. The model also makes rooftop solar feasible for private residents or other entities that cannot afford the upfront capital, and lower-income families who do not earn enough to owe taxes that could be slashed through the credit. Third-party ownership becomes even more important since the Inflation Reduction Act extended the federal investment tax credit for solar, advocates say.
“We’re focused on getting more folks and organizations and farmers and businesses to own more of the energy that’s around their properties — whether wind, solar, geothermal,” said Jason MacDuff, president of Greenpenny, an Iowa-based, sustainability-focused bank that funds many third-party-owned solar projects. “They should be able to harness the power and be able to deploy it so they can preserve their own resources. That’s important for economic development, especially in rural areas.”
The Bad River Tribe in northern Wisconsin was able to install three solar-powered microgrids with battery storage through third-party ownership, since they are not regulated by the Public Service Commission or subject to state law as a Native American tribe that gets power from an electric cooperative. The nonprofit that partnered with the tribe on the project, Cheq Bay Renewables, argued in a public comment in the Vote Solar case that third-party ownership is a social justice and equity issue.
“Equity has risen in importance across all Federal and State decisions, and should be applied to TPF [third-party financing],” Cheq Bay Renewables president William Bailey wrote in the public comment in the Vote Solar case. “TPF is just another financing tool to allow a more rapid and equitable expansion of clean energy. … This docket is not about one family, but rather could set policy throughout the state.”
Years of work crafting climate and clean energy plans have left New England states in a prime position to take advantage of renewable energy incentives in the historic climate bill enacted by Congress over the summer, advocates say.
“We’ve worked really hard to create fertile ground for this type of thing — in five of the six states, you have climate laws already passed,” said Sean Mahoney, executive vice president of the Conservation Law Foundation. “The states have prepared for this day. And now the Inflation Reduction Act is going to provide them with the resources to execute on it.”
The Inflation Reduction Act, or IRA, will allocate an estimated $369 billion over 10 years for energy security and climate change measures, according to the Congressional Budget Office. (It also includes many other forms of aid, including $64 billion to extend the Affordable Care Act and $4 billion for drought relief efforts in 17 western states.)
The wide-ranging climate change measures include tax credits for renewable energy production and storage, loans and grants for energy transmission projects and transmission planning, grants and rebates to replace heavy-duty vehicles with zero-emission vehicles, and financial assistance for clean energy technology manufacturing.
There are also rebates for consumers who install heat pumps and other energy-saving retrofits in their homes. Tax credits are available for the purchase of new or used electric vehicles by income-qualified buyers.
Passage of the law has generated “a whole bunch of enthusiasm” among the members of NECEC, a clean energy trade organization, because they see the coming injection of federal resources and private investment that will attract as an economic buttress in the face of inflation and an “up and down economy,” said Jeremy McDiarmid, vice president for policy and government affairs.
The Northeastern states overall are well positioned to jump on these opportunities because of the policy groundwork that has already been laid, he said.
“Climate targets, energy efficiency goals and programs — all of this makes them competitive,” he said.
Every New England state except New Hampshire has adopted a climate law obligating them to greenhouse gas emissions reductions. Most must cut emissions in half by 2030, and by 100% as of 2050.
Rhode Island has also passed a law requiring 100% of its electricity to be offset by renewables by 2033.
The incentives in the IRA can enhance some of the state-level programs already in place, such as by stacking federal tax credits on top of existing credits for electric vehicles or energy efficiency work, said Charles Rothenberger, climate and energy attorney for Save the Sound, in Connecticut. That state’s CHEAPR program provides incentives ranging from $750 to $4,250 for plug-in hybrid and battery electric vehicles, with the highest incentives for income-qualified buyers.
Other funding streams could help get clean energy or emissions reduction programs off the ground that have previously failed to win approval because of cost concerns, he said.
Because the federal funding has a limited time span, “states can’t take their eyes off the ball,” Rothenberger said. “The goal is to try to get as much done as we can quickly. We can make some structural changes at the state level to make some long-term progress, and show proof of concept through the federal funds.”
Indeed, the IRA’s focus on creating green jobs and green infrastructure could be transformative in how people live and do business, said Amy Boyd, vice president for climate and clean energy policy at the Acadia Center, a clean energy advocacy group that works in Massachusetts, Connecticut, Rhode Island and Maine. And those changes will not be easy or necessary to undo over time, she said.
“As technology moves forward, it doesn’t move back,” she said. “No one’s going to take the insulation out of their house so they can be colder, have more asthma and pay higher bills.”
The act also provides money to the Environmental Protection Agency to help the agency meet the requirements of President Joe Biden’s Justice 40 initiative, which calls for 40% of certain federal investments to benefit disadvantaged communities, Mahoney said. That includes money for frontline communities to address prior wrongs, something the Conservation Law Foundation is particularly interested in, he said.
Billions of dollars are available to help states figure out how to transition to a transportation system that doesn’t rely on gas or diesel, he said.
“We work in a lot of rural areas — how do you make the transportation system work there?” he said. “And in more-dense areas, there are now dollars available to help fulfill the promise of public transit that hasn’t been met in the past.”
In Vermont, passage of the IRA is “galvanizing the need for change” among lawmakers, who seem eager to act, said Peter Sterling, executive director of Renewable Energy Vermont, a clean energy trade association. He said one state senator recently told him that climate change is one of the top three issues he hears about when he’s out campaigning.
The tax credits for renewable energy production make it an ideal time to increase the state’s renewable portfolio standard, something advocates have been pushing for several years, Sterling said.
“Passage of the IRA is the extra shot in the arm Vermont needed to move forward to a 100% renewable energy future,” he said. The IRA also includes money to help states remove the barriers to wide-scale adoption of renewable energy, such as interconnection and transmission bottlenecks. New England will be competitive in vying for those dollars, McDiarmid said, as Connecticut, Maine, Massachusetts, New Hampshire and Rhode Island are already partnering on an initiative exploring ways to improve the electric transmission system to best integrate offshore wind and other renewable resources.
Smaller, regional banks and credit unions are increasingly looking to help homeowners finance solar installations in a sign of growing recognition of the opportunities in clean energy finance.
In the Midwest, Iowa-based Decorah Bank & Trust is among the latest to begin marketing loans for solar and other clean energy projects. The community bank recently relaunched a digital subsidiary called Greenpenny to serve residential and commercial customers in Iowa, Illinois, Missouri, Minnesota and Wisconsin.
It joins longtime Twin Cities clean energy lender the Center for Energy and Environment and a handful of credit unions and other community banks offering products in a space traditionally dominated by larger, national firms.
Clean energy advocates are hopeful the availability of local lenders will increase options for borrowers and provide a greater comfort level for those who might be less inclined to trust online lenders or large national banks.
Jeremy Kalin, a partner with Avisen Legal who helped the Minnesota Credit Union Network create its CU Green solar loan program, said typical residential borrowers are sensitive to “long-term value and trust” when looking for lenders. A personal connection to a bank or credit “makes a difference.”
The process often starts with referrals from solar installers. St. Paul-based All Energy Solar offers Greenpenny and Center for Energy and Environment loans to customers, as well as national lenders. “Historically, we find the national players pushing the envelope here very consistently with innovations and competing with each other to offer a diverse array of financing options that will help each customer to get the most value out of their project,” said Ryan Buege, All Energy Solar’s vice president of sales and marketing. Still, he said, if more banks developed clean energy loans, more consumers would likely become more comfortable installing systems.
Jessica Reis, vice president of communications and marketing for Greenpenny, said the bank creates a transparent loan process with no hidden fees or upfront charges, a contrast with some national lenders who use such fees to lower interest rates. The bank calls every customer who applies and communication continues via phone or email.
Greenpenny relaunched last year after struggling with an earlier rollout during the pandemic. Now the Iowa credit union has been adding staff to manage a growing portfolio. Decorah Bank & Trust CEO and President Ben Grimstad said his father, Larry, had started lending to organizations doing renewable energy projects decades ago because of his environmental interest.
Decorah, home to Luther College, has a strong ecological ethos that allowed the bank to gain experience financing more than 100 local projects, most of them solar. Grimstad wanted to expand the bank beyond Decorah and decided to create a digital offering to leverage the bank’s experience with clean energy.
“We are about a year and a half into it and it’s gone pretty well,” he said.
Greenpenny provides solar loans and a green mortgage product for efficiency, geothermal, battery storage and other carbon-reducing projects. The digital bank serves residential customers as well as small- to medium-sized commercial and industrial projects, but not utility-scale wind or solar farms.
The loans are secured by the value of the equipment, from panels to storage devices. Greenpenny President Jason MacDuff said the bank tries to set up loans that match the amount clients save monthly on their utility bills from a new solar or HVAC system. The loans require no money down.
“These borrowers, by definition, are all homeowners that tend to skew pretty sophisticated and because they’re making a pretty big investment in their home, they tend to have the means to be able to do that,” MacDuff said.
A unique short-term solar loan Greenpenny offers matches the tax credit a customer receives. The customer pays a small interest payment and then pays off the loan when the federal government disperses the 26% tax credit. A second loan covers the remaining 74% of the project’s cost.
The average residential loan size is $40,000, with commercial projects from hundreds of thousands to millions of dollars. He noted that the bank may soon finance as many as seven community solar projects in Minnesota. But plenty of deals fall through because of low reimbursements for energy by utilities or other issues.
When he joined the company in 2021, he was surprised to find so few banks offering clean energy loans. “For us to accomplish the renewable energy transition this country needs, we need more banks to be in the game helping finance these projects,” MacDuff said.
In Minnesota, the largest local option remains the Center for Energy and Environment, which has established partnerships with several cities and neighborhoods and last year financed $22.7 million in projects. Of those, 145 loans totaling $3.5 million were for residential solar, up from 89 loans in 2019. Lending services director Jim Hasnik said the organization had been lending for years for efficiency improvements before it developed a solar loan in 2014.
The loans vary in term and loan-to-value size, with interest rates increasing as the length of loans climbs. Project sizes have grown, and business has been brisk this year as the popularity of solar has grown. The center requires installers to have a builder’s contractor license following a recent string of solar company bankruptcies in the state.
Solar loans remain a niche product. The Minnesota Credit Union Network’s CU Green program launched with two credit unions — Affinity Plus Federal Credit Union and Hiway Credit Union — and has seen no others join the effort. Mara Humphrey, chief advocacy and engagement officer for the network, said some credit unions have begun discussing whether to add solar loans to their portfolios, but she believes many still lack understanding of clean energy projects and will have to see demand grow before creating products for customers.
Affinity Plus had a rocky start before dropping a requirement that homeowners first hire someone to conduct a home appraisal. Members can now apply digitally for loans and receive the money the same day.
Chief Retail Officer Corey Rupp said the new solar loan program did more volume in six months than the home equity-based one did in four years.
“I think homeowners are a little more comfortable with it,” Rupp said. The credit union is now studying loans for electric vehicles, commercial efficiency, and solar projects.
Correction: The $22.7 million CEE lent was for about 1,200 loans.
Indiana solar installers knew their customers would be worse off when new, reduced rates for surplus solar generation took effect on July 1.
But changes being ushered in by utilities go far beyond what the industry had been bracing for, say solar and consumer advocates who are now challenging regulators’ interpretation of a 2017 law that gutted net metering.
All five of Indiana’s investor-owned utilities have won approval to not only slash the rate paid for customers’ surplus solar power, but also change how solar output is calculated in a way that drastically reduces the payments.
Utilities say they are protecting other customers from subsidizing those with solar panels, but advocates say the outcome threatens to put rooftop solar out of reach for all but the wealthiest customers.
“Unfortunately, utilities used the opportunity to completely change the policy, and [state regulators] went along with what utilities wanted,” said Ben Inskeep, program director at Citizens Action Coalition, a consumer and environmental advocacy group based in Indianapolis.
Indiana solar customers until now have been paid for extra solar generation at the end of each billing cycle. The amount of electricity sent back to the grid that month is subtracted from the amount of power the customer used from the grid, and any extra is paid out at a rate lower than the retail rate but robust enough to make solar panels financially viable for many customers.
The arrangement allows a homeowner, for example, to use extra daytime solar generation to offset evening grid power use, but they can’t bank solar credits in the summer to reduce their electric bill during the darker winter months.
A bill (SA309) signed by Gov. Eric Holcomb in 2017 put the state on a path to phasing out net metering by 2047. Meanwhile, it let utilities begin paying solar customers a lower rate when solar penetration reached 1.5% of their summer peak load, or by July 2022.
CenterPoint, previously known as Vectren, was the first utility to reach that benchmark and early last year filed a request to institute the new, lower rate — known as the “excess distribution generation” or EDG rate. CenterPoint also proposed switching from monthly net metering to a new model known as “instantaneous netting,” in which customers pay the full retail rate for all power used from the grid, and all solar power sent back to the grid is paid at the much lower EDG rate. The arrangement turns out so badly for customers that advocates like Inskeep refer to it as “no netting.”
The Indiana Utility Regulatory Commission approved CenterPoint’s full request in April 2021 despite arguments from consumer and solar advocates that the plan oversteps what’s called for in the 2017 law.
“SA309 does not authorize instantaneous netting. It made no mention of changing the netting interval,” Inskeep said.
In March 2021, NIPSCO had submitted testimony seeking an EDG tariff with monthly netting. But NIPSCO withdrew that proposal and sought instantaneous net metering after the commission’s decision on CenterPoint. Utilities AES, Indiana Michigan (I&M) Power, and Duke Energy also sought the same instantaneous netting arrangement. The commission approved all of the proposals — most recently Duke’s on July 6.
The Office of Utility Consumer Counsel, a governmental office set up to advocate for consumers, joined solar advocates in arguing against instantaneous netting, saying it would be inconsistent with SA309.
But the commission has argued, including in its Jan. 26 approval of I&M’s proposal, that the intent of SA309 was to end net metering, and instantaneous netting would basically be a way to do that. The commission acknowledged that customers would save less money through instantaneous netting, but invoked an argument long used by utilities against solar energy: that the savings of customers with solar would be costs shifted onto customers who don’t have solar.
Duke Energy echoed this sentiment in response to Energy News Network questions about the change to instantaneous netting.
“The intent of the legislation is to help ensure that customers who do not own solar generation are not subsidizing those who do,” said Duke spokesperson Angeline Protegere, noting that 2,600 customers in Duke’s Indiana service territory have solar.
“Even though they generate some of their own power, solar customers still rely on electric infrastructure such as power lines, and the new rate reflects the costs of that. It’s important to realize that customers ultimately pay for the credits we give to solar customers.”
Advocates including the Indiana Distributed Generation Alliance and Citizens Action Coalition appealed the commission’s decision on CenterPoint’s proposal and won a favorable ruling in the Indiana Court of Appeals.
But now the matter is before the state Supreme Court, and the appeals court decision is negated until the higher court hears the case, with oral arguments scheduled to start Sept. 15.
“This is a matter of law,” said Laura Arnold, executive director of the Indiana Distributed Generation Alliance. “The commission and CenterPoint have been trying to portray that the General Assembly intended to allow instantaneous netting, but that is just not true.”
Under SA309, the EDG rate paid for energy from solar is equivalent to 125% of the average hourly market rate during that month. Using this calculation, CenterPoint originally proposed to pay their customers 3.1 cents per kilowatt-hour for solar, and NIPSCO proposed 2.6 cents.
Utilities have increased the prices they plan to pay customers for solar as market power prices have risen due to the war in Ukraine, to the 4 to 5 cents per kilowatt-hour range; meanwhile retail prices customers pay for power from the grid have also risen. Duke’s retail rate is 16 cents per kilowatt hour for an average residential customer, Protegere said. (CenterPoint and NIPSCO did not respond to requests for comment.)
Brad Morton, founder and CEO of Morton Solar, told the commission that the switch to instantaneous netting and EDG rates “grossly lengthens the customer investment pay-back period,” with instantaneous netting at the 3.1 cents per kilowatt-hour originally proposed by CenterPoint changing the typical residential solar payback period from the current 7- to-10 years to 21 years.
The 3.1-cent payment rate alone, without instantaneous netting, would result in a typical payback period of 14 years, he testified. When the phaseout of the federal Investment Tax Credit is added to instantaneous netting and the EDG, it would take 25 years for a typical solar system to break even, Morton said.
Morton was the first to install solar in Vectren (now CenterPoint Energy) territory, he told the commission, and among the first to do grid-tied solar in Indiana. His family members had worked in Indiana’s coal mines, and he wants to help transform former coal mine land into solar fields, replacing declining coal mining jobs and revenue with a solar economy in the process.
Last year Morton did $2.5 million worth of solar installations in Vectren’s service area, and $3.1 million in Indiana as a whole. If the instantaneous net metering goes forth, he said he might have to stop doing business in Indiana altogether, and lay off some of his 17 staff members.
“This will be devastating to Indiana’s fledgling solar industry and result in job losses and probable market contraction to an industry that was just beginning to blossom,” he testified.
Customers who have recently installed solar are exempted for a decade, governed by the old terms through 2032. But that just barely covers a typical pay-back period, so right when customers would have hoped to start reaping the savings of solar, the opportunity will stagnate. Customers — like Arnold herself — who installed solar before SA309, can net meter under previous terms until 2047.
Arnold said that if utilities get their way and institute EDG plus instantaneous metering, solar would only make sense for most customers if they have a battery system to use all their energy themselves rather than sending it back to the grid for pennies. But batteries cost thousands of dollars and make the already slim margins on solar unworkable for many customers.
She noted that if “no netting” takes effect, customers would rarely install solar systems that generate more power than they need at any given time, wasting the chance to get more clean power on the grid by installing larger systems.
Arnold added that on top of the gloom facing the solar industry for years to come, there is debilitating uncertainty for customers who’ve signed solar contracts and hoped to install them by the end of the year. Duke Energy and NIPSCO have told customers they could qualify for previous net metering terms if their solar is contracted now and installed by the end of 2022. Protegere confirmed that is Duke’s plan.
But Arnold said solar developers and lenders are worried that the commission might block this arrangement, perhaps if another utility complains.
Arnold said that months ago, advocates had asked the commission to issue an opinion clarifying the deadline, to provide certainty for developers and customers, but the commission has not done so.
Inskeep noted that the changing price of power — and hence the 125% EDG rate people are paid for solar sent back to the grid — means uncertainty for anyone who is considering solar.
“It’s hard to say what your compensation will be in the future — it will change every single year,” said Inskeep, who was principal energy policy analyst at EQ Research, a clean energy consulting firm, at the time the commission decisions were playing out.
“You’re making a 25-year investment, but the value is updated on an annual basis. You have no ability to see if your investment will pay off. Utilities never make large investments for 30-year assets without having certainty for that cost recovery. Now they’re asking residential customers to take that risk — with no ability to understand when their investment will pay off or if it will never pay off.”
Many individuals and households have at least one outdated appliance — a refrigerator, a water heater or a window-mounted air conditioner that they hold onto because of the expense involved with replacing them. Yet the money they save is often more than canceled out by higher utility bills.
Upgrading outdated appliances can help low-income households stay in their homes by reducing their utility bills — and by extension, lowering their overall housing costs. The money saved can be used toward other necessities such as food or transportation to work or school.
However, it can take years for a new appliance to pay for itself through energy savings. Without incentives, it often simply doesn’t make financial sense for a low-income household to upgrade outdated appliances solely to save on energy bills. This is especially true for renters or homeowners who are unsure about how long they will remain in a given location, or who are unsure about whether they can take new appliances with them when they move.
The challenge is in bridging the gap to bring the necessary up-front investment in energy-efficient appliances within reach. That’s where organizations like Elevate and Meadows Eastside Community Resource Organization, also known as MECRO, come in. They coordinate resources such as incentives offered by utilities, grants and low-interest loans, and make them available for low-income households to eliminate this dilemma.
Through its headquarters in Chicago’s West Loop, along with offices in downstate Illinois, Michigan, Missouri, Wisconsin, Oregon and California, Elevate works to help homeowners and owners of multifamily units across the country obtain financing to improve the energy efficiency in their homes and buildings. MECRO is located on the busy 79th Street commercial corridor of Chicago’s Southeast Side and focuses its services on residents in the community. (The name Meadows in the MECRO acronym is in honor of Rufus and Everlena Meadows, the parents of Sharon “Sy” Lewis, founder and executive director of MECRO.)
Through a collaboration with the City of Chicago, ComEd and Elevate, the National Renewable Energy Laboratory utilized its trademarked ResStock tool and place-based data to develop residential energy efficiency strategies for the city’s residential building stock, primarily comprised of bungalows and other single-family homes built before 1942. Through the Chicago Advanced Building Construction project, a series of simulations was executed, which generated up to $49 billion in potential utility bill savings. An especially significant finding was that sizable savings could be achieved through installing heat pumps and other off-the-shelf technologies.
An old refrigerator uses up to three times as much electricity as a newer, energy-efficient model. Energy-certified clothes dryers use 20% less electricity than a standard dryer. Certified clothes washers require between 40% and 50% less energy and 55% less water to operate than conventional washers.
Utilities such as ComEd and Ameren in Illinois provide a number of incentives for ratepayers — such as rebates for trade-ins of old appliances — to facilitate the switch for customers to energy-efficient appliances.
Elevate has a number of funders that provide grants to heavily incentivize or provide upgrades at no cost for homeowners. In addition, in areas where utility incentives aren’t in place, the Community Development Financial Institutions Fund can provide financing, according to Jackie Montesdeoca, director of building electrification for Elevate.
“There are models where we can have a lender include energy efficiency as part of the overall rehab. We do that in the Chicago area, but that’s a model that can be replicated [in other locations]. … The underwriters or the loan officers know that high-efficiency equipment or adding a little more insulation than code requires is going to make that building more resilient [with] lower operating costs, as opposed to a building that didn’t go through those measures in their rehab,” Montesdeoca said.
According to U.S. Census Bureau data cited in a 2020 report by the American Council for an Energy-Efficient Economy, utility costs for poor households averaged 8.1% of their income, versus just 2.3% of income spent by more affluent households on utility bills.
While the lion’s share of these expenditures was for heating and cooling, household appliances accounted for a significant percentage of utility costs as well.
A comprehensive energy efficiency upgrade that includes replacing outdated appliances can translate to savings of 30% or more, according to Montesdeoca.
Yet many eligible households remain unaware of these programs, or have the mistaken belief that they do not qualify, according to Lewis.
“One of the things that I really try to push is that all of these programs are available, [but there is a] lack of information. You would think somebody who lives in Beverly” — a middle-class, racially diverse community on Chicago’s far Southwest Side — “wouldn’t be income-eligible and they wouldn’t be suffering from housing insecurity. They are. It does not matter. There are very affluent neighborhoods where people are suffering. You know, it’s a lot when you’re making a hundred thousand dollars, [but] there are eight people in your house,” Lewis said.
Reducing utility bills by replacing outdated household appliances is a vital tool in enhancing housing affordability through the knock-on effect in freeing up funds that were formerly needed for those bills — funds that can be used for other necessities that enhance overall housing affordability. Even small improvements, such as installing aerators on faucets or converting incandescent lighting to LEDs, can contribute to cumulative money savings, Lewis said.
“So, with these little aerators people think, oh, that’s just something cute. No, it’s not. It is saving you water. It’s saving you gallons and gallons and gallons of water. Is it impactful? Yes, absolutely. Will it be able to keep more people in their homes? Absolutely. Because this is now an expense that they do not have to pay on their property, that they can invest on their bills, that they can invest in their property,” Lewis said.
Nonetheless, many would-be beneficiaries find it difficult to justify the expense to replace a functional refrigerator or water heater. A lack of awareness about available incentives also contributes to resistance. It’s often necessary to educate people about how the return on investment combined with available incentives and other resources actually helps them save money in the long run, Montesdeoca said.
“Owners need a clear expectation of estimated savings related to their upfront investment. We work to make the process easy for them and break down costs along with identifying the funding gap. For a lot of small multifamily owners … these owners don’t have a lot of cash flow to play around with. So if we aren’t bringing incentives, grant dollars, or some kind of financing as a resource it is hard to otherwise make that project work. The best scenario is that we can connect the owner to the problem and the financial tools that can help get to solutions,” Montesdeoca said.
Many energy efficiency incentives are geared toward single-family homes, but multi-family building owners and renters also struggle with high utility bills. Energy-efficient upgrades for multifamily units are essential in retaining affordable housing, according to Karen Lusson, staff attorney for the National Consumer Law Center, with offices in Boston and Washington D.C.
“The multifamily building market has always been a larger challenge. With the single family, it’s about reaching the homeowner and convincing the homeowner that this makes sense. Ideally, weatherization [and related] services should be provided at zero cost to the homeowner. In terms of the multifamily building owner, there can be variances in terms of the copays. There can be sliding scale copays for the building owner. But if we’re trying to increase the availability of affordable housing, we want to make sure those incentives are large enough, and those copays aren’t so big that they lose interest, or turn down these opportunities to invest in energy efficiency,” Lusson said.
Both ComEd and Ameren provide incentives for energy-efficient appliances for multifamily units as well as for single-family homes — working in Chicago and surrounding communities in collaboration with organizations like Elevate and MECRO.
Marcia Ellis is the owner of a six-unit property in Chicago’s New City community area located on the city’s Southwest Side. The legacy building, which was constructed in 1924, has been in the family since 1984. Ellis received a free energy assessment through Elevate, a loan through Community Investment Corporation and $44,697 in incentives from ComEd and Peoples Gas Energy Efficiency Programs to cover the cost of lighting retrofits, roof and pipe insulation, bathroom and kitchen aerators, LED lighting, a new high-efficiency boiler and other improvements. The return on investment? An estimated $2,380 in estimated annual savings, not to mention happy tenants.
MECRO worked with a senior in the community to improve the energy efficiency of her 100-year-old three-flat. Along with weatherstripping, insulation and replacement doors, the dwelling was fitted out with all-new appliances in each unit, according to Lewis.
“She gets three new air conditioners. … And she’s got a freezer in the basement that you could put a body in. It’s not energy efficient. She got a brand-new freezer. She got a stove and a refrigerator for three units, and a deep freezer. And she had her grandson’s college refrigerator. It’s not energy efficient. So, she got one of those. She got a new furnace and a new water heater. So, every appliance in her house is energy efficient.
“I visit her from time to time. You can tell the difference. You can literally tell the difference,” Lewis said.
And while making the conversion from gas or other carbon-based heating fuels to electric increases overall electric bills, making the switch can make up the difference by eliminating a gas bill altogether, according to Emma Baumgart, senior associate for communications at Elevate.
“With electrification [there] is the added benefit of having no gas bill. And especially in Chicago, People’s Gas has high fixed costs on your bill, where even if you’re not using any gas, you still are paying that monthly charge. And so that’s an added benefit of going fully electric. You still have fixed costs on your electric bill, but it’s just one instead of two. So obviously your electric bill goes up when you are converting to all electric, but by completely removing that fixed cost is another way that electrification can help with affordability,” Baumgart said.
For Lewis, a lifetime resident of Chicago’s Southeast Side, her work with MECRO in enabling residents to remain in their homes represents one way of investing in the well-being and stability of the community she calls home.
“Those things that impact the quality of life, impact how low-income housing exists in our community and how people are able to stay in their places and live comfortably,” Lewis said.
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